In the production of oil bearing formations, well bores are drilled from the surface of the earth to the level of subsurface production formations. The wells are completed by extending well casing into the well bore and cementing the casing in place. At the level of the production formation the well casing is typically perforated to establish communication of the well casing and the production formation. Production tubing is then extended through the casing and is sealed with respect to the casing by one or more packers which ensure that the upward flow of production fluid is restricted solely to the production tubing.
In most cases production formations, especially deep formations, are under gas pressure. The gas within the formation serves as a driving medium to force liquid constituents of the production fluid into the well casing and upwardly through the production tubing to the surface. When the wells are deep or the formation contains sufficient formation pressure for gas induced production, the diameter of the well casing at the production formation can be fairly small. For example, many wells have been completed with well casing having an internal diameter in the order of six inches. This small diameter well casing is permitted when the formation is under gas driving pressure because it is not necessary to introduce pumps, gas lift valves or other production apparatus into the casing in order to achieve production.
After production of petroleum products from a reservoir over a long period of time, typically the gas pressure of the formation becomes depleted sufficiently that efficient production can no longer be accomplished by means of in situ pressurized gas. It is well known that far less than half of the crude oil in an oil-bearing subsurface formation has typically been produced at the time formation pressure is depleted. Since large quantities of crude oil remain in the formation, obviously it is desirable to provide alternative means for accomplishing oil production. One suitable means for oil production is the introduction of gas into well casing and controlled introduction of gas into the production tubing of the well in order that oil and other liquid constituents standing in the tubing string can be lifted to the surface for production. Gas lift production of liquid from wells has been quite successful over the years in continuing production of oil from wells which may be otherwise substantially nonproduceable. In the gas lift method of oil production, a number of gas lift valves are located in spaced relation along the length of the tubing string. These valves are pressure responsive and function automatically to introduce gas from the casing into the tubing string as necessary to induce upwardly flowing oil to continue flowing upwardly until it reaches the surface production equipment.
Gas lift mechanisms take two general forms, i.e., fixed gas lift valves which are secured within in mandrels connected at spaced locations along the length of a tubing string and retrievable gas lift valves which are capable of being inserted into and removed from the various spaced mandrels of the gas lift valve system. Since gas lift valves typically operate in a fluid handling environment wherein the fluid being handled is of corrosive and erosive nature and wherein the fluid also typically contains debris such as sand, pipe scale, etc., gas lift valves can become worn or fouled within a reasonably short period of time. In cases wherein gas lift valves are fixed within gas lift mandrels, it is of course necessary to remove the tubing string from the well when one or more gas lift valves is in need of servicing. When the tubing string is so removed, the valves are repaired or replaced and the tubing string is reinstalled into the well. Obviously, the cost of such servicing procedures is extensive and significantly affects the efficiency of production to a substantial degree. In the case of gas lift valve systems incorporating valves that are insertable and retrievable relative to the mandrels, servicing procedures can be accomplished by the use of simple and low cost servicing equipment such as wire line servicing equipment. Valves may be removed for servicing and replaced with new or overhauled valves within a reasonably short period of time with the tubing remaining in place during such servicing procedure. The well is serviced quickly and inexpensively and is placed back into production service much more quickly than is the typical case with fixed gas lift valves. In the case of fixed gas lift valves, obviously the servicing equipment that is utilized must be capable of lifting the tubing string from the well and replacing it after new or overhauled mandrels have been installed. There is no need for heavy duty tubing pulling systems when replaceable valves are utilized. The cost for servicing equipment and labor is minimized when servicing gas lift systems with retrievable valves.
From an inventory standpoint, utilization of fixed valves typically requires an inventory of many more gas lift mandrels in order to accomplish typical servicing procedures. In the case of replaceable valves, the mandrels and the tubing string remain in place within the well and servicing operation is conducted simply by removal and replacement of only the gas lift valves. The inventory requirements, therefore, for replaceable valve type gas lift systems is typically much lower.
One of the disadvantages of retrievable-type gas lift valve systems is that the valves must typically be of restricted size in order to accomplish production of oil from small diameter well casings. As stated above, many thousands of wells have been drilled and completed through the use of small diameter casing. Many of these wells have been shut in due to depletion of reservoir gas. In many cases, the wells have not been placed in gas lift production simply because of the small diameter casing will only permit installation of gas lift systems with valves of restricted size which will not permit adequate flow for efficient well production. For example, in well casing having an internal diameter of six inches, when retrievable gas lift valves are employed, the gas lift valves will typically have an internal flow passage restricted to a diameter of one inch. The reason for this retriction is the requirement that the gas lift mandrels of the system have straight through passages of sufficient diameter to permit the valves of lower mandrels to be passed therethrough during installation and removal of the valves. The mandrel bodies must be constructed with a wall structure of sufficient thickness to withstand designed maximum casing pressures for the purpose of safety and to provide sufficient tensile strength for efficient support of the tubing string and to withstand the tensile loads that are typically employed during installation and removal of the production tubing. Obviously, from the standpoint of production efficiency, it is desirable to employ gas lift valves having an internal diameter larger than one inch for production of petroleum products from wells having well casing with an internal diameter no greater than six inches. Larger gas lift valves of this nature would obviously permit much more efficient production of oil and other liquid production constituents since much more gas can be introduced into the tubing string at a given casing pressure, thus enhancing the liquid lifting capability of the upwardly flowing gas in the tubing.